Gao, Rui (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC) | Wang, Xin (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC) | Yang, Zhen (Planning Department, CNPC) | Zhan, Qiang En (Planning Department, CNPC) | Zheng, Wei (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC) | Liu, Ying (Planning Department, CNPC) | Yang, Li Feng (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC) | Liu, Zhe (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC) | Wang, Zhen (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC)
Tight oil and gas reservoirs are characterized by strong heterogeneity, poor physical properties, low single well production, difficult development and others. The volumetric stimulation fracturing technology has become a key technology for the effective utilization of tight reservoirs. In the current fracturing optimization design, there are some limitations in simulating the true pattern of fracture propagations because the geological model is relatively simple and it is not necessary to consider the heterogeneity of reservoir plane. At the same time, the effect of large-scale and large-volume injection of fracturing fluid on formation permeability field cannot be neglected in the volume stimulation, and the coupling relationship between fracturing fluid loss and reservoir seepage is not considered in conventional productivity simulations so that the effective stimulated reservoir volume (SRV) cannot be calculated accurately. In this paper, a numerical simulation technology of fracturing based on rock deformation is introduced through theoretical analysis and field application. The effective SRV is analyzed quantitatively, and the optimization simulation method of volume stimulation parameters with the effective SRV as the evaluation objective is formed preliminarily, which guides the fracturing design of volume stimulation in tight oil blocks.
During the hydraulic fracturing process, the created rough fracture surface and fracturing fluids with high viscosity greatly challenge proppants placement in the thin aperture of fractures. Thus, it is essential to detailly investigate the effect of surface roughness on the proppant distribution. In addition, the multiphase flow in the rough nanoscale microfractures in the variety of orientations have not been cleared. Taking all of these into consideration; rock grain geometries, packing mechanisms, the presence of clay content, and in-situ stress field will be affected and will affect the presence of the microcracks, and consequently control the permeability and porosity of the sedimentary rock. In the failed rock after fracturing work, a processed zone where the pre-existing natural fractures get activated, and induced microcracks including intergranular and intragranular grain boundaries are brought to connect to the main fracture. Hence, the rock grain and pore size distributions at fracture processed zone are altered. This, in turn, controls the fluid transport in the rocks.
Our novel approach incorporates the image analysis software (ImageJ) by organizing desired image processing codes to study the critical features of the post-fracturing core sample, including main fracture roughness, mechanical rock properties, crack density, grain, and pore size distributions. Tennessee sandstone was undergone the hydraulic fracturing test and polished on a cross-section perpendicular to the main fracture. This cross-section was recorded by the high-resolution SEM images after ion-milling. Corresponding grain size and pore size distributions are studied at each representative location with respect to its distance to the main fracture to probe alterations of the fracturing process from the core sample original state. The results of grain size and pore size distributions are compared. The discussions of their alterations mechanisms and their effects on the rock porosity and permeability are analyzed.
We find that the roughness presence of fractures strongly increases conduits open to fluid flow. In addition, our developed image processing code perfectly captured the rock grains with the promising precision. Further, we are able to observe the grain size deduction due to the incremental intragranular grain boundaries while intergranular grain boundaries are still majorities outside the fracture processed zone (FPZ). Grain size renders a lognormal distribution at each representative location and coincides with the permeability distribution of most reservoir rocks. Grain size averages also match the literature values with reasonable uncertainties (20%). The pore size distribution and its average value vary spatially. Results from this study kindle the insights of the heterogeneity of the fractured formation with proper petrophysics parameters quantitatively. We also found that the aspect ratio from 2D image analysis does not reflect the significance in the mechanics.
This novel approach will commit to supporting the lab measurements, gives field preliminary hydraulic fracturing performance assessment and lower the cost needed for hydraulic fracturing design.
All static properties are input into the model. Table 1 shows the properties input and their source 2. Depending on the frac job pumped (let's assume it has 3 different proppant types) fracture sub-regions are created into the grid, each of them with a length proportional to the percentage of that proppant pumped versus the total job, with permeability equal to in-region proppant permeability and with compaction curves equal to in-region proppant conductivity degradation curves (see Figure 4).
ABSTRACT: Microbially enhanced coalbed methane (MECBM) recovery is a novel method to increase gas production by injecting nutrient with/without microorganisms in depleted CBM wells. However, to be effective, methanogens require that nutrient must be delivered efficiently by aqueous solution to a maximally large reservoir volume for microbial colonization. This study seeks to improve understanding of solute transport, nutrient delivery and microbial gas generation in naturally fractured reservoirs that are both pristine and hydraulically fractured. An equivalent multi-continuum method is adopted to characterize fracture and matrix in coal that is regarded as a dual-porosity dual permeability model. An aperture evolution model includes increments related to shear dilation and hydraulic, mechanical, and propped opening to estimate permeability change. In this study, we mainly investigate permeability evolution and mineral concentration accumulation in different fracture types during injection. A field-scale numerical simulation is established to define the effectiveness of nutrient delivery in real reservoir. The complex pre-existing fracture pattern in the coalbed is represented by an overprinted discrete fracture network (DFN) to capture the natural heterogeneity and anisotropy of fracture permeability. A simplified PKN model is adopted to simulate hydraulic fracture propagation based on linear elastic fracture mechanics (LEFM). We find that the natural fracture network plays a significant role when stimulating the MECBM reservoir, at all scales, and impacts the evolution of the hydraulic fracture. Based on the simulated cases, hydraulically stimulated fracture pathways, especially when connecting with a natural fracture network, optimally deliver nutrient remote from the injection well, thereby increasing nutrient delivery. However, large proppant embedment occurring at low strength coal plays an important role in impeding nutrient delivery within propped fractures.
Coalbed methane (CBM) contributes a significant portion of the global unconventional natural gas resource and production. A rapid expansion of CBM development has occurred since about 2000 in the United States, primarily in the San Juan, Power River, Illinois, and Black Warrior basins (Ritter et al., 2015). The discovery that up to 20% of natural gas, including CBM, is microbial in origin has stimulated interest in microbially enhanced CBM (Rice and Claypool, 1981). Recent field- and laboratory-scale experiments have shown that active and ongoing generation of microbial methane generations pervades some sedimentary basins (Cokar et al., 2013; Kirk et al., 2012; Ulrich and Bower, 2008). If CBM can be microbially stimulated, the productive lifespans of depleted microbial CBM wells can be extended, including the generation of additional microbial methane from areas without a prior history of gas production.
ABSTRACT: In this paper, we present a new parameterization of the hydraulic fracturing modeling which allows the use of a coupled flow/geomechanics reservoir simulator to predict fracture propagation. To do this we used our in-house reservoir simulator (OpenSim) which implements a fully coupled flow/geomechanics formulation, where the fluid-flow is modeled following conventional black-oil model. To simulate the hydraulic fracturing process, we define a critical strain to allow the fracture to propagate which can be conceptually related to the stress intensity factor. The permeability of fractured blocks is related to its strain assuming that the deformation is associated with the presence of a local fracture. Once a given block reaches the critical conditions, both its mechanical properties and permeability/strain behavior are modified to mimic that of a fractured block. Leak-off is naturally included in our model as the fluid transfer between fractures and matrix is ruled by the usual flow parameters (permeability, pressure, and saturation). Proppant transport is not considered explicitly, however, the water saturation distribution can be used to build a proxy for the proppant distribution. We present results for realistic models and run sensitivities to the different model parameters.
The ultimate determinant of hydraulic fracturing success is the economic production of natural gas enhanced by the fracturing process (Vermylen and Zoback, 2011). However, the determination of the ideal fracture design, well production operation and field development are plagued with uncertainty on both characterization and physical mechanisms controlling the processes (Britt et al. 2016, Ciezobka and Salehi, 2013, Ciezobka et al. 2016, Garcia et al., 2013, Higgins-Borchardt, 1976, Kahn et al. 2017, Stroisz et al. 2013, Suarez-Rivera et al. 2013).
Numerical simulation models play a key role in the design and implementation of stimulation schemes in unconventional reservoirs (Adachi et al. 2007, Lecampion, 2018, McKetta and Vargas-Silva, 2016, Petunin, 2013). Such models can be interrogated under different scenarios to obtain optimal designs. Ultimately, the resulting fracture system can be incorporated into a reservoir simulation model to assess the reservoir performance after the stimulation.
Hydraulic fracturing has been widely used for unconventional reservoirs including organic-rich carbonate formations for oil and gas production. During hydraulic fracturing, massive amount of fracturing fluids are pumped to crack-open the formation and only a small percentage of the fluid is recovered during the flowback process. The negative effects of the remaining fluid on the formation such as clays swelling and reduction of rock mechanical properties have been reported in literatures. However, effects of fluids on source rock properties, especially the microstructures, porosity and permeability, are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and corresponding changes in permeability and porosity are reported.
Two sets of tight organic-rich carbonate source rock samples were examined. One sample set was sourced from the Middle East field and the other was an outcrop from Eagle Ford Shale that is considered to be analogous to the one from the Middle East field. Three fracturing fluids, namely 2% KCl, 0.5 gpt slickwater and synthetic seawater, were used to treat the thin-section of the source rock and core samples. Modern analytical techniques such as SEM and EDS were used to investigate the source-rock morphology and mineralogy changes prior and after the fluid treatment at micron-scale level. Porosity and permeability as a function of confining pressures were quantified on core samples to investigate changes in flow properties due to the fracturing fluids treatments.
The SEM and EDS results prior to and after fracturing fluid treatments on the source rock samples showed the microstructural changes in all three fluids. In 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of micro-fractures was slightly more noticeable for samples treated with 2% KCl in comparison to slickwater at the micron-scale level. In one sample, dissolution of organic matters was captured in slickwater fluid treated rock sample. Some mineral precipitation and new micro-fractures generation were observed for samples treated with seawater. The new micro-fractures generation and mineral dissolution through the fluid treatment would result in the increases in both porosity and permeability, while the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stresses for the core plug samples. This effect on absolute gas permeability increase has an important implication for hydrocarbon recovery from unconventional reservoirs.
This study provides experimental evidences at different scales that aqueous-based fracturing fluid may potentially have positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new or re-opening of old microfractures. This observation will be beneficial to the future usage of fresh and seawater based fluids in stimulating gas production for organic-rich carbonate formations.
This paper describes three applications of a fully integrated hydraulic fracturing, reservoir, and wellbore simulator. The simulator describes hydraulic fracturing, shut-in, and production in a single continuous simulation. It describes multiphase effects (using either the black oil model or a compositional fluid model), thermal effects, transport of tracers and/or non-Newtonian fluid additives, stress shadowing from fracture propagation, and poroelastic stress effects from depletion, and uses a detailed proppant transport algorithm. It uses constitutive relations that smoothly transition from equations for flow through an open crack to equations for flow through a closed crack (with or without proppant). In the first example, we build a simulation model of Staged Field Experiment #3, a well-known historical dataset. Our result is compared with other published simulations and is matched to 15 years of production data. The simulation shows how the transport and settling of proppant in the fracture during injection and shut-in are impacted by processes such as clustered and hindered settling. Gel crosslinking and breaking are described with first-order reaction rate constants. In the second example, we perform a sensitivity analysis on cluster spacing in a generic slickwater fracturing treatment in a horizontal well. The simulations show complex interactions between stress shadowing, fracture propagation, proppant transport, and multiphase flow. The sensitivity analysis indicates that minimizing near-wellbore pressure drop is critical for improving production. Closer cluster spacing decreases near-wellbore pressure drop by providing more conduits for flow. In the third example, we simulate a vertically stacked parent/child scenario. Depletion of the overlying parent well leads to upward propagation from the child well and direct frac hits. The frac hits remobilize proppant as water sweeps into the parent well fractures, displacing gas. In the
Understanding proppant-transport and -deposition patterns in a hydraulic fracture is vital for effective and economical production of petroleum hydrocarbons. In this research, a numerical-modeling approach, combining the discrete-element method (DEM) with single-/multiphase lattice Boltzmann (LB) simulation, was adopted to advance understanding of the interaction between reservoir depletion, proppant-particle compaction, and single-/multiphase flows in a hydraulic fracture. DEM was used to simulate effective-stress increase and the resultant proppant-particle movement and rearrangement during the process of reservoir depletion caused by hydrocarbon production. Simulated pore structure of the proppant pack was extracted and used as boundary conditions in the LB simulation to calculate the time-dependent permeability of the proppant pack. We first validated the DEM-LB numerical work flow, and the simulated proppant-pack permeabilities as functions of effective stress were in good agreement with laboratory measurements. Furthermore, three proppant packs with the same average particle diameter but different diameter distributions were generated to study the role of proppant-size heterogeneity (variation in particle diameter). Specifically, we used the coefficient of variation (COV) of diameter, defined as the ratio of standard deviation of diameter to mean diameter, to characterize the heterogeneity of particle size. We obtained proppant-pack porosity, permeability, and fracture-width reduction (closure distance) as functions of effective stress. Under the same effective stress, a proppant pack with a higher diameter COV had lower porosity and permeability and larger fracture-width reduction. This was because the high diameter COV gave rise to a wider diameter distribution of proppant particles; smaller particles were compressed into the pore space between larger particles with increasing stress, leading to larger closure distance and lower porosity and permeability. With multiphase LB simulation, relative permeability curves were obtained, which are critical for larger-scale reservoir simulations under various effective stresses. The relative permeability of the oil phase was more sensitive to changes in geometry and stress, compared with the wetting phase. This was because the oil phase occupied larger pores; compaction of the proppant pack affected the structure of the pores, because the pores were farther from the grain contacts and thus more susceptible to collapse. It is also interesting to note that when effective stress increased continuously, oil relative permeability increased first and then decreased. This nonmonotonic behavior was the result of the nonmonotonic development of pore structure and oil connectivity under increasing stress.
Liang, Tianbo (China University of Petroleum, Beijing and University of Texas at Austin) | Luo, Xiao (University of Texas at Austin) | Nguyen, Quoc (University of Texas at Austin) | DiCarlo, David A. (University of Texas at Austin)
Experimental results indicate that (1) shut-in delays the production, and it is unnecessary for regaining the matrix permeability, and that (2) shut-in allows more water imbibed into the matrix before flowback. Furthermore, shut-in delays hydrocarbon production while extending the contact time between the trapped fracturing fluid and the formation. The latter may cause other types of formation damage: clay swelling (Madsen and Müller-Vonmoos 1989; Caenn et al. 2011; Gupta et al. 2013), matrix softening and proppant embedment (Alramahi and Sundberg 2012; Das et al. 2014), or fine migrant/ clay dispersion (Bazin et al. 2009). Conclusions An experimental platform is developed in this work that simulates the fracturing-fluid invasion as well as the flowback during hydrocarbon production occurring in the reservoir rock near the fracture face. Regaining of the rock permeability to hydrocarbon is obtained and compared with the changes of phase saturations in real time by CT scans for the entire period of the experiment. It is found that capillary discontinuity at the fracture face causes the majority of permeability reduction for the water-wet system; the saturation profile within the invaded zone, instead of the total water saturation, determines the degree of permeability reduction. However, it can be selfcured over time through the capillary-driven imbibition; the smaller the rock permeability, the greater the time period this self-mitigation process would take. Shut-in treatment allows the hydrocarbon production to start after the water block that is caused by capillary discontinuity is cleaned up. However, the treatment itself does not accelerate the cleanup process; on the contrary, it may slow down this process and further harm the ultimate hydrocarbon production.
Vijayvargia, Utkarsh (Cairn Oil & Gas, Vedanta Limited) | Goyal, Rajat (Cairn Oil & Gas, Vedanta Limited) | Anand, Punj Sidharth Saurabh (Cairn Oil & Gas, Vedanta Limited) | Tiwari, Shobhit (Cairn Oil & Gas, Vedanta Limited)
Raageshwari Deep Gas field is located in RJ/ON 90/1 Block in western India is a retrograde gas condensate unconventional volcanic reservoir. It consists of streaks of low permeability sand which require hydraulic fracturing to achieve commercial production. Plug and perf stage technology along with limited entry was used to ensure that most of the productive pay was stimulated. Production data, Frac and Reservoir parameter were evaluated vis-à-vis Productivity Index (PI) and interdependencies were understood.
Multiple stages in a particular well were stimulated by hydraulic fracturing with each stage having from 1 to 6 perforation clusters to ensure maximum kH coverage. Different treatment designs varying in job size, proppant type, concentration and pumping rates were prepared and executed based on the formation type, net pay and petrophysical properties. After flowback and initial cleanup, the wells were hooked to the production facility. Memory production logging was then conducted in a time phased manner and the interpreted data was used to determine the PI evolution of individual cluster of all the 93 stages in 15 wells.
Time lapse PI of individual clusters as well as specific stages were plotted against: Proppant pumped per net pay Average permeability Effective porosity Total proppant pumped Elevation depths of the Fatehgarh, Basalt and Felsic formations of the reservoir stretching from north to south of the field.
Proppant pumped per net pay
Total proppant pumped
Elevation depths of the Fatehgarh, Basalt and Felsic formations of the reservoir stretching from north to south of the field.
Important observations resulted from this exercise such as: The top most basalt stages are attributing a large portion of the 15 wells total cumulative production. It outperformed the shallower Fatehgarh sands which were thought to be more prolific. Well PI clearly supports the changes expected in the reservoir quality from north to south of the field and is in line with the OH logs. PI of wells in a particular area shows gradual improvement in contrast to the other wells PI. Positive effects of flowing back an inferior quality pay before fracturing the upper superior quality pay.
The top most basalt stages are attributing a large portion of the 15 wells total cumulative production. It outperformed the shallower Fatehgarh sands which were thought to be more prolific.
Well PI clearly supports the changes expected in the reservoir quality from north to south of the field and is in line with the OH logs.
PI of wells in a particular area shows gradual improvement in contrast to the other wells PI.
Positive effects of flowing back an inferior quality pay before fracturing the upper superior quality pay.
This study will not only assist in determining the optimum proppant pumped per net pay height for different formations but also facilitate in eliminating frac stages in a well which would result in significant cost reduction in upcoming development campaign of 42 wells.
This holistic workflow will be used for refining the number of frac stages in a well as well as determining an ideal proppant quantity for a particular stage in volcanic pays. Detailed analysis of production data supported in identifying the key frac and reservoir parameters which subsequently will aid in improving hydraulic fracturing efficiency. Representative case histories of production results assisted in finalizing well services activities to improve the overall well PI.